1. Field of the Disclosure
The present disclosure generally relates to a connector establishing a fluid-tight connection to a downhole tubular. More particularly, the present disclosure relates to a connector establishing a fluid connection between a bore of a downhole tubular and a lifting assembly and/or a fluid supply.
2. Description of the Related Art
It is known in the well drilling industry to use a top-drive assembly (e.g., a quill thereof) to apply rotational torque to a series of inter-connected tubulars (commonly referred to as a drillstring comprised of drill pipe) to drill subterranean and subsea oil and gas wells. In other operations, a top-drive assembly may be used to install casing strings to already drilled wellbores, in which case the series of inter-connected tubulars may comprise a casing string or a drillstring connected to a casing string. As such, the present disclosure is not limited to a drillstring, but may also apply to other structures such as a casing string or a drillstring connected to a casing string. The top-drive assembly may include a motor, either hydraulic, electric, or other, to provide the torque to rotate the drillstring, which may in turn rotate a drill bit at a distal end of the well.
Typically, the drillstring comprises a series of threadably-connected tubulars (drill pipes) of varying length, typically about 30 ft (9.14 m) in length. Typically, each section, or “joint” of drill pipe includes a male-type “pin” threaded connection at a first end and a corresponding female-type “box” threaded connection at the second end. As such, when making-up a connection between two joints of drill pipe, a pin connection of the upper piece of drill pipe (e.g., the new joint of drill pipe) is aligned with, threaded, and torqued within a box connection of a lower piece of drill pipe (e.g., the former joint of drill pipe). In a top-drive system, the top-drive motor may also be attached to the top joint of the drillstring via a threaded connection on a quill of the top-drive.
During drilling operations, drilling mud is pumped through the connection between the top-drive and the drillstring. The drilling mud may travel through a bore of the drillstring and exits through nozzle or ports of the drill bit or other drilling tools downhole. The drilling mud performs various functions, including, but not limited to, lubricating and cooling the cutting surfaces of the drill bit. Additionally, as the drilling mud returns to the surface through the annular space formed between the outer diameter of the drillstring and the inner diameter of the borehole, the mud carries cuttings away from the bottom of the hole to the surface. Once at the surface, the drill cuttings are filtered out from the drilling mud and the drilling mud may be reused and the cuttings examined to determine geological properties of the borehole.
Additionally, the drilling mud may be useful in maintaining a desired amount of head pressure upon the downhole formation. As the specific gravity (e.g., density) of the drilling mud may be varied, an appropriate “weight” may be used to maintain balance in the subterranean formation. If the mud weight is too low, formation pressure may push back on the column of mud and result in a blow out at the surface. However, if the mud weight is too high, the excess pressure downhole may fracture the formation and may cause the mud to invade the formation, resulting in damage to the formation and/or a loss of drilling mud.
As such, there are times (e.g., to replace a drill bit, log, run casing, etc.) where it is desirable to remove (e.g., “trip out”) the drillstring from the well and it becomes desirable to pump additional drilling mud (or increase the supply pressure) through the drillstring to displace and support the volume of the drillstring retreating from the wellbore to maintain the well's hydraulic balance. By pumping additional fluids as the drillstring is tripped out of the hole, a localized region of low pressure (e.g., suction) near or below the retreating drill bit and/or drillstring may be reduced and the force to remove the drillstring may be minimized. In a conventional arrangement, the excess supply drilling mud may be pumped through the same direct threaded connection between the top-drive and drillstring as used when drilling.
As the drillstring is removed from the well, successive sections (e.g., a stand of drill pipe) of the retrieved drillstring are disconnected from the remaining drillstring (and the top-drive assembly) and stored for use when the drillstring is tripped back into the wellbore. Following the removal of each joint (or series of joints) from the drillstring, a new fluidic connection may be established between the top-drive and the remaining drillstring. However, breaking and re-making these threaded connections, two for every section of drillstring removed, is time consuming thus slows down the process of tripping out the drillstring.
In addition to the above, a drillstring may be used as the mechanism to convey and land the casing string into position. As the drillstring is lowered, successive sections of drillstring may be added to lower the drillstring (and attached casing string) further. Once the casing has been cemented in place the drillstring may then be detached from the casing string and the drillstring may be removed from the well.
It should be understood that other types of “lifting assemblies” may be used instead of a top-drive assembly. For example, an elevator and lifting bales may be connected directly to a hook or other lifting mechanism to raise and/or lower the casing and/or drill pipe while hydraulically connected to a pressurized fluid source (e.g., a mud pump, a rotating swivel, an IBOP, a TIW valve, an upper length of tubular, etc.). This may be used when “running” casing or drill pipe on drilling rigs not equipped with a top-drive assembly.
In this regard, GB2435059 discloses a hydraulic connector which uses a seal to selectively connect to the exposed top end of the drillstring. For example, FIGS. 2a and 2b (collectively referred to as “FIG. 2”) here, show a hydraulic connector 10 disclosed in GB2435059. Hydraulic connector 10 includes an engagement assembly including a main or primary cylinder 15 and a extendable portion 20 slidably engaged and configured to reciprocate within cylinder 15. As shown, extendable portion 20 includes a hollow tubular rod 30 configured to be slidably engageable within cylinder 15 so that a first (e.g., lower) end of tubular rod 30 may protrude outside a distal end of cylinder 15 and a second (e.g., upper) end may be contained within cylinder 15. At a first (lower) end, cylinder 15 includes an end-cap 42 through which the tubular rod 30 may be able to reciprocate. The tubular rod 30 is slidably disposed within cylinder 15 such that extendable portion 20 telescopically extends through the cylinder 15 between a retracted position (e.g., FIG. 2a) and an extended position (e.g., FIG. 2b).
Referring still to FIG. 2, a sealing assembly 60 comprising seals 62 is shown located on first end of tubular rod 30. The sealing assembly 60 is shaped to fit into a proximal end (e.g., box 3 of FIG. 1) of a string of downhole tubulars 4. The sealing assembly 60 and seals 62 are configured to engage the top end of a string of downhole tubulars 4 when extendable portion 20 is in its extended position, thereby providing a fluidic seal between hydraulic connector 10 (and top-drive assembly 2) and the string of downhole tubulars 4.
Referring again to FIG. 2, the extendable portion 20 includes a cap 40 mounted on second (upper) end of tubular rod 30. As shown, hydraulic connector 10 further includes a piston 50 slidably mounted on tubular rod 30 inside cylinder 15. As shown, piston 50 is free to reciprocate between the cap 40 and the end-cap 42. As such, the inside of the cylinder 15 may be divided by the piston 50 into a first (lower) chamber 80 and a second (upper) chamber 70. The first and second chambers 80 and 70 may be energized with air and drilling mud respectively. First chamber 80 may be in fluid communication with an air supply via a port 92, which may selectively pressurize first chamber 80. Second chamber 70 may be provided with drilling mud from the top-drive 2 via a socket 90, which may (as shown) be a box component of a rotary box-pin threaded connection.
In the disposition of components shown in FIG. 2a, the piston 50 and cap 40 are touching, so that drilling mud cannot flow from the second chamber 70 to the string of downhole tubulars 4. FIG. 2b shows an alternative position of the cap 40 with respect to piston 50. As shown in FIG. 2b, with the cap 40 and piston 50 apart, holes 35 are exposed in the side of the cap 40. These holes 35 provide a fluid communication path between the second chamber 70 and the interior of the tubular rod 30. Thus drilling mud may flow from the second chamber 70 to the string of downhole tubulars 4, via the holes 35 in the cap 40 and the tubular rod 30 when cap 40 is displaced above piston 50.
To extend the extendable portion 20, so that the sealing assembly 60 and seals 62 engage the downhole tubulars 4, the pressure of the fluid in the second chamber 70 of the connector may be increased by allowing flow (e.g. drilling mud) from the top-drive assembly 2. The air in the first chamber 80 may be at a pressure sufficiently high to ensure that the piston 50 abuts the cap 40. As the pressure of the drilling mud increases, the force exerted by the drilling mud on the piston 50 and cap 40 exceeds the force exerted by the air in the first chamber on the piston 50 and the air outside the hydraulic connector 10 acting on the extendable portion 20. The cap 40 may then be forced toward the end-cap 42 and the extendable portion 20 extends. The projected area of the cap 40 may be greater than the projected area of the piston 50 such that the piston 50 remains abutted against cap 40 as the extendable portion extends. Thus, whilst the extendable portion 20 is extending, the holes 35 may not be exposed and drilling mud cannot flow from the top-drive 2 into the string of downhole tubulars 4.
Once the sealing assembly 60 and seals 62 are forced into the open threaded end of the upper end of the string of downhole tubulars 4, thereby forming a fluidic seal between the extendable portion 20 and the open end of the drill string 4, the extendable portion 20, and hence cap 40, are no longer able to extend. In contrast, as the piston 50 is free to move on the tubular rod 30, the piston 50 may be forced further along by the pressure of the drilling mud in the second chamber 70. The holes 35 are thus exposed and drilling mud may be allowed to flow from the second chamber 70, through the extendable portion 20 and into the string of downhole tubulars 4. The pressure of the air in the first chamber 80 may then be released until retraction of the extendable portion 20 is required.
As described above, the hydraulic (e.g., fluidic) connector 10 disclosed in GB2435059 may replace a traditional threaded connection between a top-drive 2 and downhole tubulars 4 during tripping operations of the downhole tubulars 4 into or out of a well.
The hydraulic connector disclosed in GB2435059 may include a pressurised control (e.g., airline) hose connected to the first chamber in order to repeatedly recharge the first chamber with pressurised air in order to retract the extendable portion 20. In certain circumstances it may be desirable to rotate the hydraulic connector, for example to transmit a torque from the top-drive 2 to the downhole tubulars 4 without any hose connections to the first chamber, which may otherwise limit rotation.
Embodiments of the present disclosure seek to address this and other issues.